Tubing anchoring and movement reducing system

ABSTRACT

The present invention provides a ¼ turn tubing anchor catcher for use in tubing strings within petroleum wells. The tubing string may also include a pump for increasing the delivery of petroleum through the well bore. The ¼ turn tubing anchor catcher can be set by a quarter turn. The ¼ turn tubing anchor catcher may act as an anchor that prevents rotation caused by the pump. The ¼ turn tubing anchor may also act as a catcher if the structural integrity of one or more portions of the tubing string fails. The present invention also provides an anchoring and movement reducing system that comprises a ¼ turn tubing anchor catcher, a pump and an torque anchor section. The system anchors the tubing string against rotation caused by the pump. The system may also act as a catcher if the structural integrity of one or more portions of the tubing string fails.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority from continuation-in-part of U.S. patent application Ser. No. 14/311,322 filed Jun. 22, 2014 and entitled Quarter Turn Torque Anchor and Catcher, which is itself a continuation-in-part of U.S. patent application Ser. No. 13/716,075 filed on Dec. 14, 2012 and entitled Quarter Turn Tension Torque Anchor. The entire disclosures of these priority documents and all related applications or patents are incorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to tools for petroleum wells generally, including wells accessing heavy crude. In particular, the present invention relates to a ¼ turn tubing anchor catcher and its use in a system for anchoring tubing and reducing or eliminating movement, which may be caused by a downhole pump, within in a well conduit.

BACKGROUND OF THE INVENTION

A tubing string is used within a petroleum well to position downhole tools proximal to one or more underground geological formations that contain petroleum fluids of interest. The tubing string may also be referred to as production tubing or a production string. The tubing string is made up of sections of individual pipe joints that are typically threadedly connected to each other. The tubing string extends within a bore of the well. The well bore is typically completed with casing or liners. The completed well bore may also be referred to as a well conduit. The tubing string can carry various downhole tools into the well conduit. For example, downhole tools can be used for various purposes including anchoring the tubing string within the wellbore at a desired location and to limit movement of the tubing string. Downhole tools can also be used to stimulate and capture production of petroleum fluids. The tubing string is also the primary conduit for conducting the petroleum fluids to the surface.

Known tubing anchors use either a combination of right and left hand threads, or are limited to one thread orientation. Examples of such tubing anchors are shown in U.S. Pat. No. 3,077,933 to Bigelow and in Canadian patent no. 933,089 to Conrad. Disadvantages of such tubing anchors include the expense of manufacturing the threaded portions, the threads may be susceptible to corrosion and the threads may be difficult to, or unable to, unset if they become filled with sand or corroded. With the new technology of fracing, the industry has adopted a heavier weight casing to be able to handle the bends and ‘S’ curves that are drilled today. A heavier weight casing wall makes the interior diameter of the casing smaller. This change in diameter, combined with the wells drilled with deviations and horizontal applications, makes the setting of the older design (multiple revolutions) tubing anchor catchers and packers hard to set as it is hard to feel, or detect, at surface when the tools is set due to the friction on the side walls and having to workout the tubing twist going around bends in the well bore.

Another type of tubing anchor shown in U.S. Pat. No. 5,771,969 and corresponding Canadian patent no. 2,160,647 to Garay avoids the aforementioned threads and instead uses a helical bearing to transform rotational movement into linear movement for setting and unsetting the tubing anchor. The helical bearing also accommodates shear pins for secondary unsetting if required. The use of one component, namely the helical bearing, to perform several functions has the advantage over the previous prior art of being less expensive to manufacture and less susceptible to seizing.

Artificial-lift pump systems are used to collect the petroleum fluids from the surrounding geological formations into the well bore and up to the surface. Examples of artificial-lift pumping systems include sucker-rod pumping systems and progressive cavity (PC) pumping systems. PC pumping systems, including multi-lobed, high capacity PC pumping systems, use a motor that is positioned at the surface of the well for rotating a drive rod that is positioned within the tubing string. The drive rod may also be referred to as the rod string. The drive rod is connected to and rotates a rotor within a stator section of the downhole pump. The stator may be threadedly connected to the tubing string. Rotation of the rotor, relative to a stationary stator, causes the pumping action that pushes the petroleum fluids to the surface through the tubing string.

Pumping operations can cause movement and vibrations within the tubing string. In particular, high capacity PC pumping systems can cause high amplitude movements and vibrations at various frequencies. The movements and vibrations can cause the drive rod to move undesirably within the tubing string and the tubing string to move undesirably within the well conduit. The movement of these well components can cause damage to the tubing string, the downhole tools and equipment carried by the tubing string or other parts of the well conduit. For example, movements vibrations caused by high capacity PC pumping systems can cause mechanical failure or backing off of the tubing string, which can be lost by falling into the well conduit. Losing the tubing string, and the downhole tools attached thereto, forces a shut-in of the well until the lost equipment can be recovered, repaired and/or replaced.

Movements caused by the high capacity PC pumping system can also interfere with intervention tools or measurement tools that are introduced into the well conduit from surface. For example, the movements can crush capilliary lines that are used to introduce chemical diluents into a well conduit, such as chemicals to break up wax buildups. The movements can also interfere with measurement tools, so that pressure or temperature gauges on wire lines cannot acquire accurate downhole measurements.

Furthermore, vibrations can travel up the tubing string and may cause mechanical problems with the well's surface equipment, for example the tubing string's top drive and the motor that drives the drive rod.

SUMMARY OF THE PRESENT INVENTION

The present invention provides a ¼ turn tubing anchor catcher that acts to reduce or stop movement of a tubing string within a wellbore. The ¼ turn tubing anchor catcher may also catch the tubing string and hold the tubing string in place if a part of the tubing string disconnects or fails above ¼ turn tubing anchor catcher.

The ¼ turn tubing anchor catcher may be used as part of a system for tubing anchoring and movement reduction or elimination for use with a tubing string within a petroleum well. The system may include at least the following components: a ¼ turn tubing anchor catcher section, a pumping section and a torque anchor section. In a preferred embodiment, these components of the system are threadedly connected within a tubing string. The ¼ turn tubing anchor catcher section may be positioned above the pumping section and the torque anchor section may be positioned below the pumping section.

The movement and vibrations generated by the pumping section may relate to the mechanical pumping action of the pumping section and, possibly, also with a misalignment of the drive rod and the tubing string. As the drive rod rotates, it may contact portions of the tubing string, which may generate vibrations within the tubing string.

The ¼ turn tubing anchor catcher section and the torque anchor section each comprise one or more slips that engage, for example by a direct mechanical contact, the inner surface of the well conduit, for example the inner surface of the casing. The mechanical connection of the ¼ turn tubing anchor catcher section and the torque anchor section to the well conduit above and below the pumping section may reduce, restrict or prevent movements and vibrations that are generated by the pumping section.

One example embodiment of the present invention provides a system for reducing or eliminating movement with a well conduit. The system comprises: a ¼ turn tubing anchor catcher section that comprises one or more slips that engage an inner surface of the well conduit; a pumping section for pumping petroleum fluids through the well conduit; and a torque anchor section that comprises one or more slips that engage the inner surface of the well conduit. Wherein the ¼ turn tubing anchor catcher section, the pumping section and the torque anchor section are each threadedly connected within a tubing string with the ¼ turn tubing anchor catcher is positioned above the pumping section, which is positioned above the torque anchor section.

Another example embodiment of the present invention provides a method of setting a ¼ turn tubing anchor and movement reducing or eliminating system within a well conduit. The method comprises the steps of: landing a tubing string within the well conduit, wherein the tubing string is connected to the system, the system comprises: a ¼ turn tubing anchor catcher section with a slip that is engagable with the well conduit; a pumping section; and a torque anchor section with a torque anchor slip that is engagable with the well conduit. The method also comprises the steps of setting the torque anchor so that the torque anchor slip moves into contact with the well conduit; pre-setting the ¼ turn tubing anchor catcher section; and applying torque and tension to the tubing string so that the slip and the torque anchor slip both engage the well conduit.

BRIEF DESCRIPTION OF THE DRAWING FIGURES

Embodiments of the invention will now be described, by way of example only, with reference to the accompanying drawings, wherein:

FIG. 1 is an elevation side view of an example embodiment of a ¼ turn tubing anchor catcher;

FIG. 2 is a mid-line cross-sectional view taken along line 2-2 in FIG. 1;

FIG. 3 is a mid-line cross-sectional view of FIG. 1 showing the ¼ turn tubing anchor catcher with its slips extended;

FIG. 4 is a perspective view of an example embodiment of a mandrel for use as part of the ¼ turn tubing anchor catcher of FIG. 1;

FIG. 5 is an enlarged view of an example embodiment of a groove that forms part of the mandrel of FIG. 4, showing a pin from the tubing anchor catcher engaged in the groove, in a run-in position;

FIG. 6 is the view of FIG. 5 showing the pin in a set position;

FIG. 7 is a mid-line cross-sectional view of an example embodiment of a ¼ turn tubing anchor catcher, in the run-in position;

FIG. 8 is a mid-line cross-sectional view of the ¼ turn tubing anchor catcher of FIG. 7, in the set position;

FIG. 9 is a side elevation view of an example embodiment of a ¼ turn tubing anchor catcher;

FIG. 10 is a mid-line, sectional view of the ¼ turn tubing anchor catcher of FIG. 9; and,

FIG. 11 is an exploded isometric view of the ¼ turn tubing anchor catcher of FIG. 9.

FIG. 12 is an enlarged view of a portion of FIG. 12.

FIG. 13 is a side elevation view of an example embodiment of a catcher positioned within a well bore.

FIG. 14 is a cross-sectional view taken along line 14-14 in FIG. 13.

FIG. 15 is a schematic depiction of one example embodiment of an anchoring and movement reducing system for use in a well conduit.

FIG. 16 is a side elevation view of an example embodiment of a torque anchor section for use with the system of FIG. 15.

FIG. 17 is a cross-sectional view of the torque anchor of FIG. 16, as viewed along line 17-17 in FIG. 16 with a well conduit included.

DESCRIPTION OF PREFERRED EMBODIMENTS

FIGS. 1 to 8 depict one example embodiment of a ¼ turn tubing anchor catcher 10 for use with an anchoring and movement reducing system 1000, also referred to herein as the system 1000. The phrase “movement reducing system” encompasses at least both concepts of decreasing and completely stopping movement within a well conduit 12 that is caused by an artificial lift pumping system within the system. The ¼ turn tubing anchor catcher 10 may be inserted within the well conduit 12 (see FIGS. 13 and 14), such as a wellbore casing. FIGS. 1 and 2 depict the ¼ turn tubing anchor catcher 10 in an unset, or “run-in”, orientation in which it can be run inside the well conduit 12 on a tubing string. Safety subs 14A, B may be attached to a mandrel 20 of the ¼ turn tubing anchor catcher 10 having attachment means, such as an inner threaded lower end 22 and an outer threaded upper end 24. In this embodiment, the ¼ turn tubing anchor catcher 10 may be run down the well conduit 12 on the tubing string in the downhole direction indicated by arrow 16. Arrow 17 indicates the opposite direction within the well conduit 12, namely the up-hole direction. It is noted, however, that terms such as “up”, “down”, “forward”, “backward” and the like are used to identify certain features of the ¼ turn tubing anchor catcher 10 when placed in a well conduit. These team are not intended to limit the ¼ turn tubing anchor catcher's use or orientation. Further, when describing the invention, all terms not defined herein have their common art-recognized meaning.

The ¼ turn tubing anchor catcher 10 has an upper end 10A and a lower end 10B. The tubing anchor catcher 10 may comprise of a drag body 40, a slip cage 60 and a biasing member 94, all of which are mounted over the mandrel 20. The drag body 40 houses a drag means, in the form of one or more drag blocks 42, for spacing the ¼ turn tubing anchor catcher 10 away from the inner wall 13 of the conduit 12. The drag blocks 42, for example three or four drag blocks 42, may be generally evenly spaced circumferentially about the ¼ turn tubing anchor catcher 10. Each drag block 42 has a drag spring to urge the outer surface 46 of the drag block against the well conduit's inner wall. Upper and lower drag retaining rings 48, 50 keep the drag blocks 42 removably mounted within the drag body 40. In addition to keeping the ¼ turn tubing anchor catcher 10 spaced from the well conduit 12, the contact of the drag block surface 46 the well conduit's 12 inner wall or surface 13 causes friction that urges the drag body 40 to remain stationary while the mandrel 20 moves within the rest of the ¼ turn tubing anchor catcher 10.

As will be discussed further, the drag body 40 is connected to the mandrel 20 by one or more pins 88 that extends inwardly from the drag body's 40 inner surface to engage a groove 80 on the outer surface of the mandrel 20. As described further below, in one example embodiment, the pins 88 are made from a shearable material.

The slip cage 60, which may also be referred to as a slip retainer, is also mounted on the mandrel 20 adjacent the drag body 40. In particular, the slip cage 60 is mounted on the mandrel 20 above the drag body 40 (i.e. in direction 17). The slip cage 60 may house one or more radially, movable slips 62. For example, three slips 62 are depicted as being evenly spaced about the slip cage 60, although this is not intended to be limiting as the ¼ turn tubing anchor catcher 10 described herein may operate with one or more slips 62. Each slip 62 has an outer surface with teeth 63 for gripping the inner wall 13 upon contact. The teeth 63 may comprise upward gripping teeth 63B and downward gripping teeth 63A. The slip 62 may also have an inner surface with opposed, outwardly inclined edges with an upper edge 64A and a lower edge 64B. A fastener in the form of a socket head cap screw 65 is fastened to the drag body 40 and is located within each of a plurality of elongate slots 66 spaced circumferentially about the slip cage 60, preferably between each slip 62. The cap screw 65 is adapted to contact upper and lower shoulders 68A, B at each end of the slot 66, which forms a stop means to prevent the slip cage 60, and the drag body 40, from separating.

A cone element 70 is mounted about the mandrel 20 at an upper end of the slip cage 60. The cone element 70 comprises an upper edge 70A and a lower edge 70B. The lower edge 70B forms a first conical surface whose inclined surface wedges under the slips 62 when the ¼ turn tubing anchor catcher 10 is moved into a set position. Likewise, an upper edge of the drag body 40 forms a second conical surface 54 whose inclined surface also wedges under the slips 62 when the ¼ turn tubing anchor catcher 10 is moved into a set position. However, the first and second conical surfaces 70B, 54 may not actively contact the slips in the unset position. A slip spring 76 urges each slip 62 radially inwardly into the slip cage 60 and away from the well conduit 12 while in the unset position (FIG. 2).

FIG. 3 depicts the ¼ turn tubing anchor catcher 10 in the set position with the slips 62 extended outwardly for engaging the inner surface 13 of the well conduit 12. The slips 62 are extended due to either or both of the conical surfaces 70B, 54 moving underneath the slips 62. For example, when the conical surface 54 moves underneath the slip 62, the spring 94 may be compressed, from below due to the movement of the mandrel 20 and the tension in the tubing string, and force the first conical surface 70B underneath the slip 62.

FIG. 4 depicts the mandrel 20 as including an upper end 20A and a lower end 20B. As described above, the upper and lower ends 20A, B may each comprise threaded connections for connecting the mandrel 20 to the tubing string. As shown in FIG. 2, the upper end 20A comprises a box threading and the lower end 20B comprises a pin threading. At least one groove 80 is formed on the mandrel's outer surface 26, as best seen in FIGS. 4 to 6. The groove 80 is dimensioned (width, depth) to slidingly accommodate a protruding portion of the pin 88 that extends therein threaded through a hole 56 in the drag body 40. The lower retaining ring 50 retains the drag blocks 42 within the drag body 40. The ¼ turn tubing anchor catcher 10 may comprise one or more sets of grooves 80 and pins 88. For example, the ¼ turn tubing anchor catcher 10 may have three sets of grooves 80 and three sets of associated pins 88 that are generally evenly radially spaced about the mandrel 20.

As depicted in FIGS. 5 and 6, the groove 80 may comprise a C-shape with shoulders 82 and 86 defining a first arm 80A of the groove 80 and shoulders 84 and 92 defining a second arm 80B of the groove 80. The two arms 80A, B of the groove 80 are connected by central portion 80C that is defined by walls 86, 87, 89 and 90. Wall 90 separates the first and second arms 80A, B.

As seen in FIGS. 5 and 6, which is an enlarged view of groove 80, a portion 88 a of the pin 88 protrudes into the groove 80 and is seated against the shoulder 92 in the run-in (i.e. un-set) position. To move the pin 88 to the set position at shoulder 82, the tubing string can be manipulated at surface so as to move axially, i.e. by pulling or pushing, and rotationally, i.e. by turning, so as to similarly manipulate the mandrel 20. Due to the drag blocks 42 frictionally engaging the inner surface 13 of the well conduit 12, the drag body 40 and the slip cage 60 remain relatively fixed as the mandrel 20 and the rest of the tubing string, are manipulated from surface. As mandrel 20 is pulled, for example about one inch, in direction 17, the pin 88 slides relative to mandrel 20 in direction A so as to engage the shoulder 84. Thereafter, the mandrel 20 can be lowered, for example about 6 to 7 inches, and turned, for example, a quarter turn to the left. The turning is about the longitudinal axis of the tubing string and, therefore, the ¼ turn tubing anchor catcher 10. This manipulation causes the pin 88 to move from shoulder 84, generally along walls 89, 87 and 86 to rest in shoulder 86 of the first arm 80A. When the pin 88 is in shoulder 86, the ¼ turn tubing anchor catcher 10 is in a pre-set position. The tubing string, and the mandrel 20 can be turned freely to the left. Pulling the tubing string and, therefore, the mandrel 20 upwards in direction 17 will cause the pin 88 to move into shoulder 82. When the pin 88 is in shoulder 82, at least the conical surface 54 has moved under the slips 62 and the ¼ turn tubing anchor catcher 10 is set with the slips 62 engaged with the inner surface of the well conduit.

In this embodiment, when viewed in vertical elevation with the top of mandrel 20 upwards, groove 80 is in the shape of a reverse “C”, although this is not intended to be a literal graphical description of shapes that will work, as other shapes will work other than exact C-shapes as may mirror images of the groove 80.

To release the slips 62, the tubing string and, therefore, the mandrel 20 can be manipulated at surface. For example, the mandrel 20 can be moved relative to the rest of the ¼ turn tubing anchor catcher 10, so that the pin 88 moves out of shoulder 82. As shown in FIG. 6, the mandrel 20 can be pushed down so that the pin 88 moves along line F. With a quarter turn to the left the pin will move along line H and then a straight pulling up of the tubing string and mandrel 20 will cause the mandrel 20 to move so that the pin 88 ends up in shoulder 84. When the pin 88 has moved out of the first arm 80A of the groove 80, the conical surface 54 moves out from under the slips 62 and the spring 76 will cause the slips 62 to retract back into the slip cage 60.

When the ¼ turn tubing anchor catcher 10 is in the set position and in the event of a break in the tubing string, etc, which may cause the tubing string to fall down into the well (i.e., in direction 16), the tension in the tubing string is lost. This causes the weight of the tubing string to bear on the upper safety sub 14A, which will bear on the biasing member 94. The biasing member 94 will compress, from the weight of the tubing string above, and act against the upper edge 70A of the cone 70. This action causes the upper teeth 64A to more directly engage and bite into the inner surface 13 of the well conduit 12. For example, the greater the amount of tubing string weight that compresses the spring 94, the harder, or more directly, the upper teeth 64A will engage the inner surface 13 of the well conduit 12. When the downwardly gripper teeth 64A are more directly engaged into the inner surface 13 of the well conduit 12, the upper teeth 64A can hold the weight of the tubing string above the ¼ turn tubing anchor catcher 10, for example, until such time that the tubing string can be recovered at surface.

If it is not possible to move pin 88 in the groove 80 so as to unset slips 62, for example due to packing of sand or other materials into the groove 80, the slips 62 may be unset by applying a sufficient upward tension on the tubing string and the mandrel 20. In one embodiment, the upward tension is of a sufficient amplitude to shear the pins 88, which form the primary connection between the drag body 40 and the mandrel 20. Then the mandrel 20 may move upward (i.e. in the direction of arrow 17), relative to the drag body 40, which causes the second conical surface 54 of the drag body 40 to move out from under the slips 62. This allows the slips 62 to retract from contacting the inner surface of the well conduit. When the slips 62 are retracted, the ¼ turn tubing anchor catcher 10 may be pulled out of the well conduit 12. For example, the pin 65 may engage the lower shoulder 68B of the slot 66 so that the slip cage 60, and the drag body 40 do not separate. Alternatively, or additionally, the lower edge of the catcher body 40 may engage the lower safety sub 14 b as the tubing string is pulled upwards towards the surface (i.e. in direction 17).

FIGS. 9 to 12 depict an alternative embodiment of a ¼ turn tubing anchor catcher 100 with an upper end 100A and a lower end 100 b. The ¼ turn tubing anchor catcher 100 may comprise many of the same features as ¼ turn tubing anchor catcher 10. For example, one difference between the two ¼ turn tubing anchor catchers 10, 100 is that the pin 88 of the ¼ turn tubing anchor catcher 10 may be sheared as a secondary release mechanism, as described above. In contrast, the ¼ turn tubing anchor catcher 100 may comprise a pin 188 that is not designed to shear as a secondary release mechanism. The ¼ turn tubing anchor catcher 100 may comprise one or more shear pins 72 that are mounted on the lower cone 41 to drag body 40. The shear pins 72 are made of a material that will shear in response to a lower shearing force than the shear force required to shear the pin 188. The second conical surface 54 is formed on the upper end of cone 41 (see FIG. 12). Cone 41 slidably mounts onto mandrel 20 so that conical surface 54 in combination with conical surface 70B on cone 70 compress together along mandrel 20 to force slip 62 into the set position, as described above. The shear pins 72 provide a secondary release of slips 62 by the application of a sufficient pulling force to the tubing string so as to shear the shear pins 72. When the shear pins 72 are sheared, the conical surface 54 can move from under the slips 62 and the slips 62 can retract away from the inner surface 13 of the well conduit 12.

The ¼ turn tubing anchor catchers 10, 100 are thus designed to anchor the tubing string from movement longitudinally along the well (in both directions, up and down the well) and from rotating. The anchoring is achieved by simple setting and release procedures that require relatively little movement of the tubing string. In this instance, setting is achieved by a small pull and left hand rotation of the mandrel 20 (via the tubing string) that is adequate for the pins 88, 188 to travel the short distances within the groove 80. Further, both ¼ turn tubing anchor catchers 10, 100 can prevent a broken tubing string from falling into the well bore by the compression of the spring 94 causing the downward gripping teeth 63A to grip the inner surface 13 of the well conduit 12, as described above.

In one optional embodiment of the present invention, the slips 62 may be configured to center either or both of the ¼ turn tubing anchor catchers 10, 100 within the well conduit 12 by radially protruding from the slip cage 60 (see FIGS. 13 and 14). This may provide one or more by-pass spaces 78 between the ¼ turn tubing anchor catchers 10, 100 and the inner surface 13 of the well conduit 12, which may create high flow areas for fluids (e.g. gas) and solids (e.g. sand) to pass by the tubing anchor catchers 10, 100. The by-pass spaces 78 may also allow coil tubing to extend more easily past the ¼ turn tubing anchor catcher 10, 100. In the FIG. 14, which is provided by way of example only, depicts by-pass spaces 78 with 1.0 inch (25.4 mm) radial clearance that are created between the 4.5 inch (114.3 mm) OD of the slip cage 60 and the 6.5 inch (165.1 mm) ID of the well conduit 12.

This optional embodiment of the ¼ turn tubing anchor catchers 10, 100 may permit capillary cable to be carried downhole via the large by-pass spaces 78. In particular, the fact that the ¼ turn tubing anchor catchers 10, 100 is set and unset by longitudinal motion and a limited, quarter turn, permits its use with the capillary cable since the ¼ turn tubing anchor catchers 10, 100 may avoid wrapping of the cable around the ¼ turn tubing anchor catchers 10, 100. In contrast, prior art anchors that require multiple full (360 degree) rotations—between two to nine full rotations for setting and unsetting—cause an undesirable wrapping of the cable around the anchor, which can damage the cable. Alternately, the cables must be pre-wrapped when inserted with these prior art anchors, so that they unwrap as the anchor is twisted during setting, which is tedious and undesirable.

Optionally, the drag blocks 42 may be hardened, in comparison to prior art drag blocks, for a longer operational life. The slips 62 may optionally be made of solid high strength metal for superior durability and grip on the well conduit wall 13, and Inconel™ type springs 76 are employed for improved resistance to H₂S and CO₂. Further, the surface of the mandrel 20 may optionally be coated with Teflon® for improved resistance to H₂S and CO₂, and to help maintain mandrel strength.

FIG. 15 depicts one example embodiment of the anchoring and movement reducing system 1000. The system 1000 includes one or more pump sections 1112 for use within the well conduit 12. The well conduit 12 is formed by well casing and it includes the inner surface 13, which defines a central bore of the well conduit 12. The system 1000 is connected to a tubing string 1001 that is positioned within the well conduit 12. The tubing string 1001 may also be referred to as production tubing or a production string. For example, the tubing string 1001 can include a number of individual pipe joints or sections of multiple pipe joints that extend from the surface through the well conduit 12 to position the system 1000 at a desired location. For example, it may be desirable to position a pumping section 1112 of the system 1000 proximal to perforations in the well conduit 12 so that petroleum fluids may be conducted to the surface.

In one example, the system 1000 can include at least one pump section 1112, for example a progressive cavity (PC) pump for assisting with the delivery of hydrocarbons through the tubing string 1001 up to the surface 500. Preferably, the pump section 1112 comprises a multi-lobed, high capacity PC pump system. A high capacity PC pump comprises a rotor that rotates to the right, when viewed from above. The inventors have observed that during pumping operations, the pump section 1112 can cause movement of, and vibration along, the entire tubing string 1001. The movements and vibrations can propagate along the tubing string 1001 and possibly the well conduit 12. The inventors have also observed that the vibrations can progress into larger, swaying and oscillatory movements of the tubing string 1001 within the conduit 12. The vibrations and/or the swaying movements can damage various components and equipment within the well conduit 12, including the pump section 1112, which may cause breakage and loss of portions of the tubing string 1001. For the purposes of this description, the vibrations and the swaying movements caused by the pumping action of the pumping section 1112 are considered synonymous, regardless of any difference in the amplitude or frequency of the vibrations and swaying movements.

The system 1000 may include at least one ¼ turn tubing anchor catcher section 1106 that is positioned above the pump section 1112. The system 1000 may also include a torque anchor section 1118 that is positioned below the pump section 1112. The system 1000 may include other components, as further described below, that are connected by individual tubing joints, or sections of multiple tubing joints, to the ¼ turn tubing anchor catcher section 1106, the pump section 1112 and the torque anchor section 1118. Optionally, the other components of the system 1000 may be connected via the tubing joints above, below or inbetween the ¼ turn tubing anchor catcher section 1106, the pump section 1112 and the torque anchor section 1118.

As depicted in FIG. 15, which is not intended to be limited, one example embodiment of the system 1000 comprises the following components: a first tubing section 1100, a ¼ turn tubing anchor catcher section 1106, a second tubing section 1108, a pump section 1112 and a torque anchor section 1118. The components of the system 1000 may be arranged in the sequence described above.

The first tubing section 1100 comprises multiple sections of tubing joints that comprise the tubing string 1001 that extends along and through the well conduit 12 from the surface 500 above to at least proximal to an underground geological formation that contains the petroleum fluids of interest (not shown). Furthermore, the well conduit 12 may have one or more perforations, not shown, therethrough to provide fluid communication between the underground geological formation of interest and the inner surface 13 of the well conduit 12. For example, the perforations may be apertures, holes, or ports that are open, openable, or openable and closeable by various means known to the person skilled in the art.

The ¼ turn tubing anchor catcher section 1106 may comprise either of the example embodiments of ¼ turn tubing anchor catchers 10, 100 described herein above and depicted throughout FIGS. 1 to 14.

In one example embodiment of the system 1000, the pump section 1112 comprises a progressive cavity pump with a rotor section 1110, a stator section (not shown) and, optionally, a tag sub 1114. The tag sub 1114 may also be referred to as a tag bar or stop bushing. During pumping operations, the rotor section 1110 may be rotated by mechanical forces that originate at the surface 500, for example from an electric motor at the surface 500. Typically, the rotor section 1110 is rotated in one direction, e.g. to the right when viewed from above. The stator section remains stationary relative to the rotor section 1112. It is well known in the art how rotation of the rotor section 1110 pumps petroleum fluids up the tubing string 1001 to the surface 500. In an alternative embodiment of the system 1000, the pump section 1112 may comprise other types of downhole pumps.

In one example embodiment of the system 1000, the ¼ turn tubing anchor catcher section 1106 may be positioned above the pumping section 1112 with 1 or more tubing joints positioned therebetween. The inventor has observed that in some instance having the ¼ turn tubing anchor catcher section 1106 directly adjacent the pump section 1112 restricts the oscillatory movement near the pump section 1112, which can place a large and detrimental physical strain on the rotor section 1110. By positioning one or about two tubing joints between the pump section 1112 and the ¼ turn tubing anchor catcher section 1106 may relieve some of the physical strain on the rotor section 1110. Optionally, the ¼ turn tubing anchor catcher section 1106 may be positioned within the tubing string 1001 above the perforations in the well conduit 12 but the ¼ turn anchor catcher section 1106 is not restricted to that location within the system 1000.

The torque anchor section 1118, when positioned below the pump section 1112, prevents rotation of the pump section 1112 during pumping operations. For example, in the embodiment of the system 1000 where the pump section 1112 comprises a high capacity PC pump, the torque anchor section 1118 prevents right-hand rotation caused by the pumping operations. Stopping right-hand rotation prevents backing off, or parted tubing, and maintains the threaded connections throughout the tubing string 1001 and the system 1000. The torque anchor section 1118 may be of any torque anchor design and application known or not yet known. FIG. 16 depicts one example embodiment of the torque anchor section 1118 that may comprise a tubular body 1150 with one or more slips 1152. The one or more slips 1152 may radially extend away from an outer surface of the tubular body 1150 to engage the inner surface 13 of the well conduit 12 (as shown in FIG. 17). The one or more slips may be rigid slips, pivotable slips, floating slips, or combinations thereof. The tubular body 1150 has opposing ends that are connectible to uphole and downhole portions of the system 1000 or other components and equipment that may be positioned within the well conduit 12. For example, the tubular body 1150 may have threaded connections at each end. The torque anchor section 1118 may be positioned within the tubing string 1001 immediately adjacent and below the pump section 1112. Alternatively, there may be one or two sections of tubing joints between the pump section 1112 and the torque anchor section 1118. Preferrably, there are two tubing joints positioned between the pump section 1112 and the torque anchor section 1118 there below. The inventor has observed that providing about two tubing joints between the pump section 1112 and the torque anchor section 1118 may increase the durability and product life of the torque anchor section 1118 in comparison to torque anchor sections 1118 that are placed immediately adjacent the pump section 1112.

The slips 1152 may be actuated between a set position—engaged against the inner surface 13 of the well bore 12—and an unset position—not engaged with the inner surface 13. Optionally, the slips 1152 may be actuatable between the set and unset positions by rotation, for example by a right hand rotation of the tubing string 1001, or by another means.

When the one or more slips 1152 are engaged with the inner surface of the well conduit 12, the torque anchor section 1118 and other components of the system 1000 may, optionally, be held in a substantially concentric position within the well conduit 12. Additionally, the torque anchor section 1118 may defines by-pass spaces 1154 between the inner surface of the well conduit 12, the outer surface of the tubular body 1150. The by-pass spaces 1154, similar to by-pass spaces 78 of the ¼ turn tubing anchor catcher section 1106, may provide high flow areas for fluids (e.g. gas) and solids (e.g. sand) to pass by the torque anchor section 1118 and the pumping section 1112. The by-pass spaces 1154 also allow coiled tubing and other equipment, such as wire line gauges and capillary lines to extend past the ¼ turn anchor catcher section and the torque anchor section 1118.

Furthermore, the torque anchor section 1118 can be dimensioned to be substantially the same cross-sectional area as the stator of the pump section 1112. This dimensional matching may reduce the collection or deposition of sand on the torque anchor section 1118 and/or the pumping section 1112, which advantageously may ease the removal of the system 1000 if the well conduit 12 becomes sanded in.

In one example of the system 1000, the torque anchor section 1118 may be any torque anchor described in U.S. Pat. No. 5,636,690, U.S. Pat. No. 7,778,447, Canadian Patent No. 2,159, 659 or Canadian Patent No. 2,611,294, the entire disclosures of which are incorporated herein by reference.

Optionally, other components and equipment of the system 1000 that are connected to the tubing string 1001 may be distanced from the inner surface 13 of the well conduit 12, which may improve pumping operations. As described below, the system 1000 is set in tension, which also helps maintain the distance between the system 1000 and the inner surface 13 of the well conduit 12.

The inventor has observed that in situations where the well conduit 12 deviates from a straight line, i.e. it has one or more turns as it extends downward from the surface 500, the system 1000, while in tension may assist with aligning the drive rod with the well conduit 12. This may reduce rubbing and wearing down of the tubing string and, in some instances the casing, where the drive rod contacts the tubing string.

In another example embodiment, the system 1000 may further comprise a tubing drain 1102 and a second tubing section 1104. The tubing drain 1102 is a pressure activated means of draining the tubing string 1001 if an operator cannot remove parts of the pump section 1112 from within the well conduit 12. Optionally, the pressure activation of the tubing drain 1102 is controlled by one or more shear screws. As depicted in FIG. 15, which is not intended to be limiting, the tubing drain 1102 is positioned above the ¼ turn tubing anchor catcher section 1106. The second tubing section 1104, which may comprises one or more tubing joints, is positioned between the tubing drain 1102 and the ¼ turn tubing anchor catcher section 1106.

A third tubing section 1108 may be positioned within the system 1000 between the ¼ turn tubing anchor catcher section 1106 and the pumping section 1112. The third tubing section 1108 may comprise one or more individual tubing joints.

Optionally, a tubing hanger (not shown) may be provided proximal to the surface 500 to support the tubing string 1001. The tubing hanger may prevent fluid communication between the inside of tubing string 1001 and the well conduit 12. As a further option, a tool 1200, for example a safe tension tool, may be provided between the tubing hanger and the tubing string 1001. The safe tension tool 1200 allows manipulation of the tubing string 1001, for example rotating and axial pulling or pushing of the tubing string 1001, while maintaining, i.e. without disrupting, the tubing hanger and the fluid communication barrier that it provides.

In operation, the system 1000 can be threadedly connected within tubing joints that comprise the tubing string 1001 and positioned within a well conduit 12. The tubing string 1001 can be built to include a required number of tubing joints so that the pumping section 1112 is desirably positioned within the well conduit 12, for example proximal to the geological formation of interest, which may include positioning the pumping section 1112 proximal to perforations in the well conduit that provide fluid communication with the geological formation of interest. When the pumping section 1112 is desirably positioned, a portion of the tubing string 1001 is connected to a tubing hanger, not shown, and the tubing string 1001 is considered landed within the well conduit 12. This step may be referred to as landing the tubing string.

Following landing of the tubing string step, a surface end of the tubing string 1001 is rotated in a right hand direction until the slips 1152 of the torque anchor section 1118 initially contact the well conduit's inner surface 13. This step may be referred to as setting the torque anchor.

Following the setting of the torque anchor step, the tubing string 1001 is then lifted upwardly at surface. For example, the tubing string 1001 may be lifted one inch, or more or less. Then the tubing string 1001 may be turned a quarter turn to the left while the tubing string 1001 is lowered, for example, the same distance that it was lifted, or not. Optionally, the tubing string may be lowered about 6 or 7 inches. These steps may be referred to as pre-setting the ¼ turn tubing anchor catcher section 1106. As described above, setting the ¼ turn tubing anchor catcher section 1106 causes the ¼ turn tubing anchor catcher section 1106 to engage the inner surface 13 of the well conduit 12. Setting the ¼ turn tubing anchor catcher section 1106 will also move the torque anchor section 1118 away from the set position. However, when the tubing string 1001 is lowered during the step of setting the ¼ turn tubing anchor catcher section 1106, the torque anchor section 1118 will return to the set position with the slips 1152 returning to an initial contact position with the inner surface 13. This manipulation at surface will also cause the ¼ turn tubing anchor catcher section 1116 to rotate back to the right hand direction when the tubing string 1001 is lowered back to the original position.

Following the step of pre-setting the ¼ turn tubing anchor catcher section 1106, the tubing string 1001 is rotated to the right by applying torque and the tubing string 1001 is pulled upwardly by applying tension. The application of torque and tension to the tubing string 1001 may be simultaneous or sequential. Preferrably the torque and tension are applied simultaneously. The torque applied may be in the range of about 750 to about 2000 ft/lbs The tension applied may be about 10,000 ft/lbs. This step may be referred to as setting the system 1000. When the ¼ turn tubing anchor catcher section 1106 comprises the ¼ turn tubing anchor catchers 10, 1000, the pins 88, 188 will move along the groove 80 of the mandrel 20 to set the slips 62, as described above.

When the system 1000 is set, then vibrations and swaying movements within the tubing string 1001 that are generated by the pump section 1112 are reduced in amplitude, either partially or entirely, above the ¼ turn tubing anchor catcher section 1116 and below the torque anchor section 1118.

While the above disclosure describes certain examples of the present invention, various modifications to the described examples will also be apparent to those skilled in the art. The scope of the claims should not be limited by the examples provided above; rather, the scope of the claims should be given the broadest interpretation that is consistent with the disclosure as a whole. 

What is claimed is:
 1. A system for reducing movement of a tubing string within a well conduit, the system comprising: a. a ¼ turn tubing anchor catcher section that comprises one or more slips that are engagable with an inner surface of the well conduit; b. a pumping section for pumping fluids through the well conduit; and c. a torque anchor section that comprises one or more slips that are engagable with the inner surface of the well conduit, wherein the ¼ turn tubing anchor catcher section, the pumping section and the torque anchor section are each threadedly connected within the tubing string with the ¼ turn tubing anchor catcher positioned above the pumping section, which is positioned above the torque anchor section.
 2. The system of claim 1, wherein the ¼ turn anchor catcher section further comprises: a. a mandrel that is connectible at a first end and a second end within the tubing string, the mandrel comprising an externally facing groove; b. a slip cage that is slidably mountable about the mandrel, the slip cage comprising the one or more slips; c. a first cone element that is slidably mountable about to the mandrel, adjacent the slip cage towards a first end of the tool, the first cone element comprising a first conical surface; d. a drag body that is slidably mountable about the mandrel, adjacent the slip cage towards a second end of the tool, the drag body comprising a drag member that is sized for frictionally engaging an inner surface of the well conduit, a pin for engaging the externally facing groove, and a second conical surface; and e. a biasing member that is slidably mountable about the mandrel adjacent the first cone element for engaging the first cone element when the biasing member is compressed; wherein the ¼ turn anchor catcher section is articulatable between a run-in position and a set position, when in the run-in position the one or more slips are retracted into the slip cage and when in the set position at least the second conical surface is moved underneath the one or more slips for extending the one or more slips outward from the slip cage.
 3. The system of claim 1, wherein the pumping section comprises a multi-lobed, high capacity progressive cavity pump.
 4. The system of claim 1, wherein the torque anchor section prevents rotation of the tubing string in a right-hand direction.
 5. The system of claim 1, wherein the torque anchor section has a cross-sectional area that is substantially the same as a cross-sectional area of a stator portion of the pump section.
 6. The system of claim 1, further comprising a tubing hanger for supporting the tubing string and for providing a fluid communication barrier between an inner conduit of the tubing string and the well conduit.
 7. The system of claim 6, further comprising a safe tension tool that is positionable between the tubing hanger and the tubing string for allowing manipulation of the tubing string at a surface while maintaining the fluid communication barrier of the tubing hanger.
 8. The system of claim 1, further comprising 1 or about 2 tubing joints that are threadedly connectible within the tubing string between the ¼ turn tubing anchor catcher section and the pump section.
 9. The system of claim 1, further comprising about two tubing joints that are threadedly connectible within the tubing string adjacent each other between the pumping section and the torque anchor section.
 10. A method of setting a movement reducing system within a well conduit comprising steps of: a. landing a tubing string within the well conduit, wherein the tubing string is connected to the movement reducing system, the movement reducing system comprising: i. a ¼ turn tubing anchor catcher section with a slip that is engagable with the well conduit; ii. a pumping section; and iii. a torque anchor section with a torque anchor slip that is engagable with the well conduit; b. setting the torque anchor so that the torque anchor slip moves into contact with the well conduit; c. pre-setting the ¼ turn tubing anchor catcher section; and d. applying torque and tension to the tubing string so that the slip and the torque anchor slip both engage the well conduit.
 11. The method of claim 10, wherein the step of landing the tubing string further comprises positioning the pumping section proximal to a geological formation of interest.
 12. The method of claim 11, wherein the step of setting the torque anchor comprises a step of rotating the tubing string in a right-hand direction until the torque anchor initially contacts the well conduit.
 13. The method of claim 10, wherein the step of setting the ¼ turn tubing anchor catcher section comprises steps of: a. lifting the tubing string; and b. lowering the tubing string while turning the tubing string about a ¼ turn to the left.
 14. The method of claim 13, wherein the step of lifting the tubing string lifts the tubing string about 1 inch and the step of lowering the tubing string lowers the tubing string between 2 to 7 inches.
 15. The method of claim 10, wherein during the step of applying torque and tension to the tubing string, the torque and tension are applied simultaneously.
 16. The method of claim 10, wherein the torque applied during the step of applying torque and tension to the tubing string the torque is applied in a range of about 750 to 2000 ft/lbs.
 17. The method of claim 10, wherein the tension applied during the step of applying torque and tension to the tubing string the torque is about 10,000 ft/lbs.
 18. The method of claim 10, wherein the steps of setting a movement reducing system within a well conduit are performed at a surface above the well conduit.
 19. A method of setting a movement reducing system within a well conduit comprising steps of: a. landing a tubing string within the well conduit, wherein the tubing string is connected to the movement reducing system, the movement reducing system comprising: i. a ¼ turn tubing anchor catcher section with a slip that is engagable with the well conduit; ii. a pumping section; and iii. a torque anchor section with a torque anchor slip that is engagable with the well conduit; b. setting the torque anchor so that the torque anchor slip moves into contact with the well conduit; c. pre-setting the ¼ turn tubing anchor catcher section; and d. applying torque and tension to the tubing string so that the slip and the torque anchor slip both engage the well conduit, wherein the ¼ turn tubing anchor catcher section, the pumping section and the torque anchor section are each threadedly connectible within the tubing string with the ¼ turn tubing anchor catcher is positioned above the pumping section, which is positioned above the torque anchor section.
 20. A system for reducing movement of a tubing string within a well conduit, the system comprising: a. a ¼ turn tubing anchor catcher section that comprises one or more slips that are engagable with an inner surface of the well conduit; b. a pumping section for pumping fluids through the well conduit; and c. a torque anchor section that comprises one or more slips that are engagable with the inner surface of the well conduit, wherein the ¼ turn tubing anchor catcher section, the pumping section and the torque anchor section are each threadedly connectible within the tubing string with the ¼ turn tubing anchor catcher positionable above the pumping section, which is positionable above the torque anchor section. 